Natural gas is predominantly transported in gaseous form by pipeline. For natural gas deposits not located in close proximity to a pipeline and, thus, not feasibly transported over a pipeline, i.e., stranded or remote natural gas, the gas must be transported by other means and is often transported in liquid form as liquid natural gas (“LNG”) in ships. Natural gas storage and transport in liquid form involves a state at either cryogenic or near cryogenic temperatures (−270 degrees F. at atmospheric pressure to −180 degrees F. at pressure), which requires a heavy investment in liquefaction and re-gasification facilities at each end of the non-pipeline transport leg, as well as heavy investment in large storage tankers. These capital costs along with high energy expenditures necessary to store and transport LNG at these states tend to make the storage and transportation of natural gas in liquid form quite costly.
In recent years, transportation of stranded or remote natural gas assets as compressed natural gas (“CNG”) has been proposed, but has been slow to commercialize. CNG, which includes compressing the gas at pressures of 100 to several hundred atmospheres, offers volumetric ratios of containment between one third and one half of the 600 to 1 (600:1) volumetric ratios obtained with LNG without the heavy investment in liquefaction and re-gasification facilities.
The shipment of CNG at atmospheric temperatures or chilled conditions to −80 degrees F. is presently the subject of industry proposals. Compressing natural gas to 2150 psig (146 atm) places the gas compressibility (Z) factor at its lowest value, (approx 0.74 at 60 degrees F.) before it climbs to higher values at elevated pressures. At 2150 psig a compressed volume ratio on the order of 225:1 is attainable. Commercial tankage at 3600 psig is commonly used to pack natural gas to a compressed volume ratio of 320:1.
To effectively deliver stranded or remote natural gas into the shipping cycle it must be held in storage in quantities suited to the frequency of transport vessels and the production rate at the gas source. Loading, preferably achieved in a minimum amount of time, is also factored into this storage computation. Similarly, unloading must be into a storage system sized based on frequency of deliveries, unloading time and take away capacity of the pipeline feeding the natural gas to market. Holding a natural gas vessel at these staging points is part of the delivery costs associated with all transport modes.
CNG handling is energy intensive requiring significant compression and cooling to these volumetric ratios, and then displacing the gas upon unloading. Given the relatively high cost of storing high pressure CNG, lengthy loading and unloading times and associated cooling or reheating capacity, no commercial system is yet operational to prove the possibility of conveying bulk volumes over 0.5 bcf/day.
Accordingly, it would be desirable to provide superior natural gas concentrations than those obtainable with CNG and at moderate pressures and moderately reduced temperatures to facilitate better performance parameters than CNG, and reduce the proportionate intensity of equipment required for LNG.